EXHIBIT 99.2
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation
The following management’s discussion and analysis should be read in conjunction with our historical consolidated financial statements, located herein as Exhibit 99.3 to this Current Report on Form 8-K and in Item 8. “Financial Statements and Supplementary Data” of our 2008 Annual Report on Form 10-K (“2008 Form 10-K”). Any reference to Notes in the following management’s discussion and analysis refers to the Notes to Consolidated Financial Statements located in Exhibit 99.3 to this Current Report on Form 8-K and in Item 8. “Financial Statements and Supplementary Data” of our 2008 Form 10-K. The results of operations reported and summarized below are not necessarily indicative of future operating results. This discussion also contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, such as those set forth under Item 1A. “Risk Factors” which can be found in our 2008 Form 10-K.
As further discussed in Note 2, our consolidated financial statements for the periods presented have been adjusted (1) for the retrospective application of Financial Accounting Standards Board Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement),” (2) for the retrospective application of Financial Staff Position Emerging Issue Task Force 03-06-1, “Determining Whether Instruments Granted in Share Based Payment Transactions Are Participating Securities,” (3) for the retrospective application of Financial Accounting Standards Board Statement No. 160 “Noncontrolling Interests in Consolidated Financial Statements,” and (4) for the presentation ot the consolidated operations and financial position of Helix Energy Limited as discontinued operations following its sale in April 2009. The financial information contained in the management discussion and analysis below reflects only the adjustments described in Note 2 and any modifications associated with the two subsequent events disclosed in “Subsequent Events” below and in Note 25 of Exhibit 99.3 of this Current Report on Form 8-K. Except as discussed in “Subsequent Events” below and Note 25, no other modifications or updates to these disclosures for events occurring after March 2, 2009, the date of the filing of our 2008 Form 10-K, have been made in this Current Report on Form 8-K.
Subsequent Events
On April 27, 2009, we sold our reservoir and well technology services business held by Helix Energy Limited (“HEL”) to a subsidiary of Baker Hughes Incorporated for $25 million. HEL through its subsidiary, Helix RDS Limited is a provider of reservoir engineering, geophysical, production technology and associated specialized consulting services to the upstream oil and gas industry. As a result of the sale of HEL and Helix RDS Limited, we have presented the results of Helix RDS as discontinued operations in the accompanying consolidated financial statements. HEL and Helix RDS were previously components of our Contracting Services segment.
On June 10, 2009, we completed an underwritten secondary public offering by selling 20 million shares of common stock of our majority owned subsidiary Cal Dive International, Inc (“Cal Dive,” “CDI,” or “DVR”) held by us (“the Offering”). Proceeds from the Offering totaled $161.9 million, net of underwriting fees. The Offering remains subject to a thirty day option period under which the underwriters may sell up to an additional 3 million shares of our Cal Dive shares of common stock at $8.50 per share, the price per share under the Offering. Separately, pursuant to a Stock Repurchase Agreement with Cal Dive, upon closing of the Offering, Cal Dive simultaneously repurchased from us approximately 1.6 million shares of its shares for net proceeds of $14 million at $8.50 per share. Following the closing of these two transactions, our ownership of Cal Dive common stock has been reduced to approximately 28%. We intend to use all the proceeds from the Offering and the Cal Dive stock repurchase for general corporate purposes.
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Executive Summary
Our Business
We are an international offshore energy company that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our oil and gas business is a prospect generation, exploration, development and production company. Employing our own key services and methodologies, we seek to lower finding and development costs, relative to industry norms.
Our Strategy
In December 2008, we announced the intention to focus and shape the future direction of the Company around our deepwater construction and well intervention services. We intend to achieve this strategic focus by seeking and evaluating strategic opportunities to:
1) | Divest all or a portion of our oil and gas assets; |
2) | Divest our ownership interests in one or more of our production facilities; and |
3) | Dispose of our remaining interest in our majority owned subsidiary, CDI. |
We have engaged financial advisors to assist us in these efforts. The current economic and financial market conditions may affect the timing of any strategic dispositions by us and will require a degree of patience in order to execute any transactions. As a result, we are unable to be specific with respect to a timetable for any disposition, but we intend to aggressively focus on reducing debt levels through monetization of non-core assets and allocation of free cash flow in order to accelerate our strategic goals.
Consistent with this strategy, in December 2008 we announced the sale of our 17.5% non-operating working interest in the Bass Lite oil and gas field for $49 million in gross proceeds and in January 2009 we entered into a stock repurchase agreement with Cal Dive that resulted in us selling CDI approximately 13.6 million of CDI common shares held by us for $86 million in gross proceeds. This sale reduced our ownership interest in CDI to approximately 51%. We owned approximately 57% of CDI at December 31, 2008. Our ownership in CDI is currently approximately 28% (see “Subsequent Events” above and Note 25).
Demand for our contracting services operations is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, drilling and production operations. Generally, spending for our contracting services fluctuates directly with the direction of oil and natural gas prices. The performance of our oil and gas operations is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and excess capacity, geopolitical issues, weather and several other factors.
Economic Outlook and Industry Influences
The recent economic downturn and weakness in the equity and credit capital markets has led to increased uncertainty regarding the outlook of the global economy. This uncertainty coupled with the probable decrease in the near-term global demand for oil and gas has resulted in commodity price declines over the second half of 2008, with significant declines occurring in the fourth quarter of 2008. Declines in oil and gas prices negatively impact our operating results and cash flow. We believe that these events have contributed to the significant decline in our stock price and corresponding market capitalization. In the fourth quarter of 2008, because of the declines in our stock price and the prices of oil and natural gas, we were required to assess the fair value of our goodwill, indefinite-lived intangible assets and certain of oil and gas properties
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that resulted in us recording an aggregate of $896.9 million of impairment charges ($704.3 million for goodwill and indefinite-lived intangible assets and $192.6 million for oil and gas property impairments) (Note 2). The aggregate of all impairment charges for 2008 was $920.0 million. Further, our contracting services also may be negatively impacted by declining commodity prices as such may cause our customers, primarily oil and gas companies, to curtail or eliminate capital spending. At the moment, it is still too soon to predict to what extent current events may affect our overall activity levels in 2009 and beyond. The long-term fundamentals for our business remain generally favorable as the need for the continual replenishment of oil and gas production should drive the demand for our services. In addition, as our subsea construction operations primarily support capital projects with long lead times, that are less likely to be impacted by temporary economic downturns. We have hedged approximately 73% of our anticipated production for 2009 with a combination of forward sale and financial hedge contracts. The prices for these contracts are significantly higher than the prices for both crude oil and natural gas as of December 31, 2008 and as of the time of the filing of our 2008 Form 10-K on March 2, 2009. If the prices for crude oil and natural gas do not increase from current levels, and we have not entered into additional forward sale or financial hedge contracts to stabilize our cash flows, our oil and gas revenues may decrease in 2010 and beyond, perhaps significantly, absent offsetting increases in production amounts.
In light of the current credit crisis, in October 2008, we drew down an additional $175 million on our Revolving Credit Facility to ensure adequate and readily available liquidity to mitigate the cash flow impacts of production shut-in from Hurricanes Gustav and Ike, to fund ongoing capital projects and for hurricane remediation and repair costs. After this draw down, we had approximately $44 million (approximately $59 million as of February 27, 2009) of additional capacity remaining under our Revolving Credit Facility (including letters of credit). Further, we have reduced our planned capital expenditures for 2009 to include primarily the completion of major vessel construction projects and limited oil and gas expenditures. If we successfully implement the business plan outlined above, we believe we have sufficient liquidity without incurring additional indebtedness beyond the existing capacity under the Revolving Credit Facility.
Our business is substantially dependent upon the condition of the oil and natural gas industry and, in particular, the willingness of oil and natural gas companies to make capital expenditures for offshore exploration, drilling and production operations. The level of capital expenditures generally depends on the prevailing views of future oil and natural gas prices, which are influenced by numerous factors, including but not limited to:
• | worldwide economic activity, including available access to global capital and capital market; | ||
• | demand for oil and natural gas, especially in the United States, Europe, China and India; | ||
• | economic and political conditions in the Middle East and other oil-producing regions; | ||
• | actions taken by the OPEC; | ||
• | the availability and discovery rate of new oil and natural gas reserves in offshore areas; | ||
• | the cost of offshore exploration for and production and transportation of oil and gas; | ||
• | the ability of oil and natural gas companies to generate funds or otherwise obtain external capital for exploration, development and production operations; | ||
• | the sale and expiration dates of offshore leases in the United States and overseas; | ||
• | technological advances affecting energy exploration production transportation and consumption; | ||
• | weather conditions; | ||
• | environmental and other governmental regulations; and | ||
• | tax policies. |
Global economic conditions have deteriorated significantly over the past year with declines in the oil and gas market accelerating during the fourth quarter of 2008. Predicting the timing of any recovery is subjective and highly uncertain. Although we are currently in a recession, we believe that the long-term industry fundamentals are positive based on the following factors: (1) long term
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increasing world demand for oil and natural gas; (2) peaking global production rates; (3) globalization of the natural gas market; (4) increasing number of mature and small reservoirs; (5) increasing ratio of contribution to global production from marginal fields; (6) increasing offshore activity, particularly in Deepwater; and (7) increasing number of subsea developments. Our strategy of combining contracting services operations and oil and gas operations allows us to focus on trends (4) through (7) in that we pursue long-term sustainable growth by applying specialized subsea services to the broad external offshore market but with a complementary focus on marginal fields and new reservoirs in which we have an equity stake.
Activity Summary
Over the last few years we continued to evolve our model by completing a variety of transactions and events that have had, and we believe will continue to have, significant impacts on our results of operations and financial condition. In 2005, we substantially increased the size of our Shelf Contracting fleet and deepwater pipelay fleet through the acquisition of assets from Torch Offshore, Inc. and Acergy US Inc. for a combined purchase price of $210.2 million. We also acquired a significant mature property package in the Gulf of Mexico OCS from Murphy Oil Corporation for $163.5 million cash and assumption of abandonment liability of $32 million. Finally, we established our Reservoir and Well Technology Services group through the acquisition of Helix Energy Limited for $32.7 million and the assumption of $7.5 million of liabilities. In April 2009, we sold our interests in Helix Energy Limited for $25 million (Notes 2 and 25). In 2006, we acquired Remington, an exploration, development and production company, for approximately $1.4 billion in cash and Helix common stock and the assumption of $358.4 million of liabilities. In March 2006, we changed our name from Cal Dive International, Inc. to Helix Energy Solutions Group, Inc., leaving the “Cal Dive” name to our Shelf Contracting subsidiary, and in December 2006 completed a carve-out initial public offering of Cal Dive, selling a 26.5% stake and receiving pre-tax net proceeds of $264.4 million and a pre-tax dividend of $200 million from additional borrowings under the Cal Dive revolving credit facility.
During 2006 we committed to four capital projects which will significantly expand our contracting services capabilities: conversion of the Caesar into a deepwater pipelay vessel, upgrading of the Q4000 to include drilling capability, conversion of a ferry vessel into a DP floating production unit (Helix Producer I) and construction of a multi-service DP dive support/well intervention vessel (Well Enhancer). During 2007, we successfully completed the drilling of exploratory wells in our Bushwood prospect located in Garden Banks Blocks 462, 463, 506 and 507 in the Gulf of Mexico. In January 2009, we announced an additional discovery at the Bushwood field (see “Oil and Gas Operations” in Item 2. “Properties” elsewhere in our 2008 Form 10-K). Initial sustained production from Bushwood commenced in January 2009.
In December 2007, Cal Dive acquired Horizon for approximately $650 million. CDI issued an aggregate of approximately 20.3 million shares of its common stock and paid approximately $300 million in cash in the merger. The cash portion of the merger consideration was paid from CDI’s cash on hand and from borrowings under its $675 million credit facility consisting of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility, each of which is non-recourse to Helix. As a result of CDI’s equity issued, we recorded a $98.6 million gain, net of $53.1 million of taxes. The non-cash gain was calculated as the difference in the value of our investment in CDI immediately before and after CDI’s stock issuance.
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Results of Operations
Our business consists of contracting services and oil and gas operations. We have disaggregated our contracting services operations into three reportable segments in accordance with SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information”. As a result, our reportable segments consist of the following: Contracting Services, Shelf Contracting, Production Facilities, and Oil and Gas. The Contracting Services segment includes operations such as deepwater pipelay, well operations, robotics and reservoir and well technology services. The Shelf Contracting segment represent the results and operations of Cal Dive, in which we owned 57.2% at December 31, 2008 and approximately 51% at the time of the filing of the 2008 Form 10-K. As discussed in “Subsequent Events” above and Note 25 in Exhibit 99.3 of this Current Report of Form 8-K, in June 10, 2009 we sold approximately 21.6 million of the Cal Dive shares of common stock owned by us for net proceeds of $175.9 million.. As a result of these transactions our ownership interest in Cal Dive currently approximates 28%. All material intercompany transactions between the segments have been eliminated in our consolidated financial statements, including our consolidated results of operations.
Comparison of Years Ended December 31, 2008 and 2007
The following table details various financial and operational highlights for the periods presented:
Year Ended December 31, | Increase/ (Decrease) | |||||||||||
2008 | 2007 | |||||||||||
Revenues (in thousands) – | ||||||||||||
Contracting Services | $ | 961,926 | $ | 673,808 | $ | 288,118 | ||||||
Shelf Contracting(1) | 856,906 | 623,615 | 233,291 | |||||||||
Oil and Gas | 545,853 | 584,563 | (38,710 | ) | ||||||||
Intercompany elimination | (250,611 | ) | (149,566 | ) | (101,045 | ) | ||||||
$ | 2,114,074 | $ | 1,732,420 | $ | 381,654 | |||||||
Gross profit (loss) (in thousands) – | ||||||||||||
Contracting Services | $ | 204,796 | $ | 180,656 | $ | 24,140 | ||||||
Shelf Contracting(1) | 254,007 | 227,398 | 26,609 | |||||||||
Oil and Gas(2) | (60,601 | ) | 120,861 | (181,462 | ) | |||||||
Intercompany elimination | (26,011 | ) | (23,008 | ) | (3,003 | ) | ||||||
$ | 372,191 | $ | 505,907 | $ | (133,716 | ) | ||||||
Gross Margin – | ||||||||||||
Contracting Services | 21 | % | 27 | % | (6 | )pts | ||||||
Shelf Contracting(1) | 30 | % | 36 | % | (6 | )pts | ||||||
Oil and Gas (2) | (11) | % | 21 | % | (32 | )pts | ||||||
Total company | 18 | % | 29 | % | (11 | )pts | ||||||
Number of vessels(3)/ Utilization(4) – | ||||||||||||
Contracting Services: | ||||||||||||
Pipelay | 9/92 | % | 6/79 | % | ||||||||
Well operations | 2/70 | % | 2/71 | % | ||||||||
ROVs | 46/73 | % | 39/78 | % | ||||||||
Shelf Contracting | 30/60 | % | 34/65 | % | ||||||||
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1) | Represented by our consolidated, majority owned subsidiary, CDI. At December 31, 2008 and 2007, our ownership interest in CDI was approximately 57.2% and 58.5%, respectively. Our interest in CDI decreased to approximately 51% in January 2009. Our ownership interest in CDI decreased to approximately 28% following the completion of the Offering and the repurchase of shares by CDI (see “Subsequent Events” above and Note 25). |
2) | Includes asset impairment charges of oil and gas properties totaling $215.7 million ($192.6 million in fourth quarter of 2008). These impairment charges do not have any impact on current or future cash flow. |
3) | Represents number of vessels as of the end the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party. |
4) | Average vessel utilization rate is calculated by dividing the total number of days the vessels in this category generated revenues by the total number of calendar days in the applicable period. |
Intercompany segment revenues during the years ended December 31, 2008 and 2007 were as follows (in thousands):
Year Ended December 31, | Increase/ (Decrease) | |||||||||||
2008 | 2007 | |||||||||||
Contracting Services | $ | 195,207 | $ | 115,864 | $ | 79,343 | ||||||
Shelf Contracting | 55,404 | 33,702 | 21,702 | |||||||||
$ | 250,611 | $ | 149,566 | $ | 101,045 | |||||||
Intercompany segment profit (which only relates to intercompany capital projects) during the years ended December 31, 2008 and 2007 were as follows (in thousands):
Year Ended December 31, | Increase/ (Decrease) | |||||||||||
2008 | 2007 | |||||||||||
Contracting Services | $ | 20,945 | $ | 10,026 | $ | 10,919 | ||||||
Shelf Contracting | 5,066 | 12,982 | (7,916 | ) | ||||||||
$ | 26,011 | $ | 23,008 | $ | 3,003 |
As disclosed in Item 2 “Properties” of our 2008 Form 10-K, virtually all of our oil and gas operations are located in the U.S. Gulf of Mexico. We have one property located offshore of the United Kingdom, Camelot, that is capable of production but has been shut-in since the third quarter of 2008. Revenues associated with our U.K oil and gas operations totaled $3.9 million in 2008 and $2.7 million in 2007 on production volumes of 0.3 Bcfe and 0.6 Bcfe, respectively. We had no production from U.K properties in 2006. The total operating costs associated with our U.K oil and gas operations totaled $4.1 million in 2008, $7.3 million in 2007 and $4.9 million in 2006.
The following table details various financial and operational highlights related to our Oil and Gas segment for the periods presented (U.S. operations only as U.K. operations were immaterial for the periods presented, see above):
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Year Ended December 31, | Increase/ (Decrease) | |||||||||||
2008 | 2007 | |||||||||||
Oil and Gas information– | ||||||||||||
Oil production volume (MBbls) | 2,751 | 3,723 | (972 | ) | ||||||||
Oil sales revenue (in thousands) | $ | 253,656 | $ | 251,955 | $ | 1,701 | ||||||
Average oil sales price per Bbl (excluding hedges) | $ | 98.61 | $ | 70.17 | $ | 28.44 | ||||||
Average realized oil price per Bbl (including hedges) | $ | 92.22 | $ | 67.68 | $ | 24.54 | ||||||
Increase (decrease) in oil sales revenue due to: | ||||||||||||
Change in prices (in thousands) | $ | 91,360 | ||||||||||
Change in production volume (in thousands) | (89,659 | ) | ||||||||||
Total increase in oil sales revenue (in thousands) | $ | 1,701 | ||||||||||
Gas production volume (MMcf) | 30,490 | 42,163 | (11,673 | ) | ||||||||
Gas sales revenue (in thousands) | $ | 283,269 | $ | 324,282 | $ | (41,013 | ) | |||||
Average gas sales price per mcf (excluding hedges) | $ | 9.48 | $ | 7.46 | $ | 2.02 | ||||||
Average realized gas price per mcf (including hedges) | $ | 9.29 | $ | 7.69 | $ | 1.60 | ||||||
Increase (decrease) in gas sales revenue due to: | ||||||||||||
Change in prices (in thousands) | $ | 67,441 | ||||||||||
Change in production volume (in thousands) | (108,454 | ) | ||||||||||
Total increase in gas sales revenue (in thousands) | $ | (41,013 | ) | |||||||||
Total production (MMcfe) | 46,993 | 64,500 | (17,507 | ) | ||||||||
Price per Mcfe | $ | 11.43 | $ | 8.93 | $ | 2.50 | ||||||
Oil and Gas revenue information (in thousands)- | ||||||||||||
Oil and gas sales revenue | $ | 536,925 | $ | 576,237 | $ | (39,312 | ) | |||||
Miscellaneous revenues(1) | $ | 5,058 | $ | 5,667 | $ | (609 | ) | |||||
(1) | Miscellaneous revenues primarily relate to fees earned under our process handling agreements. |
Presenting the expenses of our Oil and Gas segment on a cost per Mcfe of production basis normalizes for the impact of production gains/losses and provides a measure of expense control efficiencies. The following table highlights certain relevant expense items in total (in thousands) and on a cost per Mcfe of production basis (with barrels of oil converted to Mcfe at a ratio of one barrel to six Mcf):
Year Ended December 31, | ||||||||||||||||
2008 | 2007 | |||||||||||||||
Total | Per Mcfe | Total | Per Mcfe | |||||||||||||
Oil and gas operating expenses(1): | ||||||||||||||||
Direct operating expenses(2) | $ | 80,710 | $ | 1.72 | $ | 80,410 | $ | 1.25 | ||||||||
Workover | 28,982 | 0.62 | 11,840 | 0.18 | ||||||||||||
Transportation | 5,095 | 0.11 | 4,560 | 0.07 | ||||||||||||
Repairs and maintenance | 20,731 | 0.44 | 12,191 | 0.19 | ||||||||||||
Overhead and company labor | 4,798 | 0.10 | 9,031 | 0.14 | ||||||||||||
Total | $ | 140,316 | $ | 2.99 | $ | 118,032 | $ | 1.83 | ||||||||
Depletion and amortization | $ | 185,373 | $ | 3.94 | $ | 217,382 | $ | 3.37 | ||||||||
Abandonment | 15,985 | 0.34 | 21,073 | 0.33 | ||||||||||||
Accretion | 12,771 | 0.27 | 10,701 | 0.17 | ||||||||||||
Impairments (3) | 215,675 | 4.59 | 64,072 | 0.99 | ||||||||||||
Total | $ | 429,804 | $ | 9.14 | $ | 313,228 | $ | 4.86 |
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(1) | Excludes exploration expense of $32.9 million and $26.7 million for the years ended December 31, 2008 and 2007, respectively. Exploration expense is not a component of lease operating expense. Also excludes the impairment charge to goodwill of $704.3 million in fourth quarter of 2008. |
(2) | Includes production taxes. |
(3) | Includes impairment charges for certain oil and gas properties totaling $215.7 million ($192.6 million in fourth quarter of 2008). |
Revenues. During the year ended December 31, 2008 our consolidated net revenues increased by 22% compared to 2007. Contracting Services gross revenues increased 43% over 2007 amounts primarily reflecting the following:
• | the addition of two chartered subsea construction vessels as well as an overall increase in utilization of our subsea construction vessels; | ||
• | commencing performance of several longer term contracts; | ||
• | increases in the utilization and rates realized for our well operations vessels; | ||
• | strong performance by our robotics division driven by a higher number of ROVs in our fleet and additional services required following Hurricanes Gustav and Ike; and | ||
• | increased sales by our Shelf Contracting business (see below), resulting from its acquisition of Horizon in December 2007 and increased work following Hurricanes Gustav and Ike. |
Our increases were partially offset by the following negative factors:
• | an increase in the number of out-of-service days for the Q4000 associated with marine and drilling upgrades. The Q4000 was out of service for most of the first half of 2008; | ||
• | weather related downtime associated with Hurricanes Gustav and Ike. |
Gross revenues for our Shelf Contracting business increased 37% in 2008 compared to 2007 primarily reflecting the revenue contribution of the Horizon assets that were acquired in December 2007 partially offset by lower vessel utilization related to winter seasonality and harsh weather conditions which continued into May 2008, and weather downtime associated with Hurricanes Gustav and Ike. Following the storm, our Shelf Contracting revenues benefitted from the increased scope of work associated with the storms including inspections, repairs and reclamation projects.
Oil and Gas revenues decreased 7% during 2008 as compared to the prior year. The decrease is primarily associated with the loss of production following the shut-in of many of our oil and gas properties following Hurricanes Gustav and Ike. Our production rates in 2008 were 27% lower than the same period last year; however our current net daily production is approximately 90% of pre-storm production volumes after adjusting for the sale of one major deepwater property in December 2008. The decrease in our revenues was partially offset by substantially higher oil and natural gas prices realized over the amounts received in 2007, which reflects near historical high prices for both oil and natural gas over the first half of 2008. Prices of both oil and natural gas decreased significantly during the second half of 2008, with price reductions accelerating in the fourth quarter of 2008.
Gross Profit. The Contracting Services gross profit increase was primarily attributable to improved contract pricing for the well operations and ROV divisions. These increases were partially offset by lower margins realized on certain longer term deepwater pipelay projects reflecting the delays in delivery of the Caesar and processing of certain change orders which prevented revenue recognition under the percentage-of-completion method (Note 2). We also recorded approximately $9.8 million of estimated losses on two contracts in which we believe the future revenue benefits will be exceeded by the estimated future costs to service the contracts (Note 2). The gross profit increase within Shelf Contracting was primarily attributable to the initial
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deployment of Horizon’s assets that were acquired in December 2007 and additional work following Hurricanes Gustav and Ike, offset by increased depreciation associated with Horizon assets and weather-related delays over the first five months of 2008 and during Hurricanes Gustav and Ike. Our 2007 Shelf Contracting operations were adversely effected by an higher number of out-of-service days referred to above, lower vessel utilization as a result of seasonal weather in the fourth quarter 2007, and increased depreciation and deferred drydock amortization.
The decrease in the gross profit for our oil and gas operations in 2008 as compared to 2007 reflects the following key factors :
• | impairment expense of approximately $215.7 million ($192.6 million recorded in the fourth quarter of 2008) related to our proved oil and gas properties primarily as a result of downward reserve revisions reflecting lower oil and natural gas prices, weak end of life well performance for some of our domestic properties, fields lost as a result of Hurricanes Gustav and Ike and the reassessment of the economics of some of our marginal fields in light of our announced business strategy to exit the oil and gas exploration and production business; we also recorded a $14.6 million asset impairment charge associated with the Devil’s Island Development well (Garden Banks Block 344) that was determined to be non-commercial in January 2008. Asset impairment expense in 2007 totaled $64.1 million, which included $20.9 million for the costs incurred on the Devil’s Island well through December 31, 2007. | ||
• | a decrease of $32.0 million in depletion expense in 2008 because of lower production which is primarily attributed to the effects Hurricanes Gustav and Ike had on our production during the latter part of the yea. This decrease was partially offset by higher rates resulting from a reduction in estimated proved reserves for a number of or producing fields at December 31, 2008. | ||
• | approximately $8.8 million of exploration expense (all in fourth quarter of 2008) compared to $9.0 million in 2007 related to reducing the carrying value of our unproved properties primarily due to management’s assessment that exploration activities for certain properties will not commence prior to the respective lease expiration dates; | ||
• | approximately $16.0 million of plug and abandonment overruns primarily related to properties damaged by the hurricanes, partially offset by insurance recoveries of $7.8 million; and | ||
• | approximately $18.8 million of dry hole exploration expense reflecting the conclusion that two exploratory wells previously classified as suspended wells (Note 7) no longer met the requirements to continue to be capitalized primarily as a result of the discontinuing of plans to progress the development of these wells in light of our announcement in December 2008 of our intention to pursue a sale of all or a portion of our oil and gas assets. In 2007, our dry hole expense totaled $10.3 million, of which $5.9 million was related to our South Marsh Island Block 123 #1 well. |
Goodwill and other intangible asset impairments. In the fourth quarter of 2008 we recorded a $704.3 million of impairment charge to write off the remaining oil and gas goodwill following our annual assessment of goodwill, which took into account the significant decrease in our common stock price as well as the stock prices of our identified peers and the rapid reduction in oil and natural gas commodity prices. We also recorded an $8.3 million impairment charge in the fourth quarter of 2008 to write off the goodwill associated with our 2005 acquisition of Helix Energy Limited as well as a related $2.4 million impairment charge to write off its indefinite life asset (trademark). These amounts are reflects as a component of income (loss) from discontinued operations in the accompanying consolidated statement of operations as Helix Energy Limited was sold in April 2009 (see “Subsequent Events” and Note 25). We separately recorded $8.1 million of reductions of goodwill associated with dispositions of oil and gas properties in 2008, which are included as a component of the gain or loss on sale of assets, net as discussed below.
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Gain on Sale of Assets, Net. The net gain on sale of assets increased by $23.1 million during 2008 as compared to 2007. In 2008 our oil and gas property sales included:
• | $91.6 million gain related to the sale of a 30% working interest in the Bushwood discoveries (Garden Banks Blocks 463, 506 and 507) and East Cameron Blocks 371 and 381; | ||
• | $11.9 million loss related to the sale of all our onshore properties; included in the cost basis of our onshore properties was goodwill of $8.1 million; and | ||
• | $6.7 million loss related to the sale of our interest in the Bass Lite field in December 2008; there was no goodwill associated with this sale as all goodwill was previously written off. The sale of the remainder (approximately 10%) of our original 17.5% interest closed in January 2009 and will be reflected in our first-quarter 2009 results. |
On September 30, 2007, we sold a 30% working interest in the Phoenix oilfield (Green Canyon Blocks 236/237), the Boris oilfield (Green Canyon Block 282) and the Little Burn oilfield (Green Canyon Block 238) to Sojitz GOM Deepwater, Inc. (“Sojitz”) for a cash payment of $51.2 million and recognized a gain of $40.4 million in 2007. We also recognized the following gains in 2007:
• | $2.4 million related to the sale of a mobile offshore production unit; | ||
• | $1.6 million related to the sale of 50% interest in Camelot, which is located offshore of United Kingdom; and | ||
• | $3.9 million related to the sale of assets owned by CDI. |
Selling and Administrative Expenses. Selling and administrative expenses of $177.2 million in 2008 were $32.2 million higher than the $145.0 million incurred in 2007. The increase was due primarily to higher overhead (primarily related to CDI’s Horizon acquisition) to support our growth. We also recognized approximately $7.4 million of expenses related to the separation agreements between the Company and two of its former executive officers (Note 22). Selling and administrative expenses as a percent of revenues were approximately 8.4% for both 2008 and 2007.
Equity in Earnings of Investments, Net of Impairment Charge. Equity in earnings of investments increased $12.3 million during 2008 as compared to 2007. Equity in earnings related to our 20% investment in Independence Hub increased $9.3 million as we reached mechanical completion in March 2007 and began receiving demand fees and tariffs as production began in the third quarter of 2007. In addition, equity in earnings of our 50% investment in Deepwater Gateway decreased by $3.5 million in 2008 as compared to 2007 due to downtime at the Marco Polo TLP following Hurricanes Gustav and Ike. These increases were offset by second quarter 2007 equity losses from CDI’s 40% investment in Offshore Technology Solutions Limited (“OTSL”) and a related non-cash asset impairment charge together totaling $11.8 million.
Net Interest Expense and Other. Net interest and other expense increased to $89.5 million in 2008 as compared to $67.0 million in the prior year. Gross interest expense of $137 million during 2008 was higher than the $107.8 million incurred in 2007 because of higher levels of indebtedness as a result of our Senior Unsecured Notes and CDI’s term loan, both of which closed in December 2007. Offsetting the increase in interest expense was $42.1 million of capitalized interest and $2.4 million of interest income in 2008, compared with $31.8 million of capitalized interest and $9.2 million of interest income in 2007. We expect interest expense to decrease in 2009 as a result of lower expected interest rates on our variable rate debt instruments. See Note 11 for detailed description of these notes. Our other income (expense) includes gains (losses) associated with transactions denominated in foreign currencies. Our foreign currency gains (losses) totaled ($10.0) million in 2008 and ($0.5) million in 2007.
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Provision for Income Taxes. Income taxes for continuing operations decreased to $86.8 million in 2008 compared to $171.9 million in the prior year. This decrease is primarily due to lower profitability in 2008. The effective tax rate of (17.6)% is not representative because of the $704.3 million non-deductible goodwill and indefinite-lived intangible assets impairment charge as discussed above. Excluding the goodwill and other intangible asset impairments, the effective tax rate of 41.2% for 2008 was higher than the 33.3% effective tax rate for same period 2007 primarily reflecting the additional deferred tax expense recorded as a result of the increase in the equity earnings of CDI in excess of our tax basis. Further, the allocation of goodwill to the cost basis for the oil and gas properties sales prior to the fourth quarter of 2008 was not deductible for tax purposes. See Note 12 for additional information regarding income taxes.
Comparison of Years Ended December 31, 2007 and 2006
The following table details various financial and operational highlights for the periods presented:
Year Ended December 31, | |||||||||||
2007 | 2006 | Increase/ (Decrease) | |||||||||
Revenues (in thousands) – | |||||||||||
Contracting Services | $ | 673,808 | $ | 446,458 | $ | 227,350 | |||||
Shelf Contracting(1) | 623,615 | 509,917 | 113,698 | ||||||||
Oil and Gas | 584,563 | 429,607 | 154,956 | ||||||||
Intercompany elimination | (149,566 | ) | (57,846 | ) | (91,720 | ) | |||||
$ | 1,732,420 | $ | 1,328,136 | $ | 404,284 | ||||||
Gross profit (in thousands) – | |||||||||||
Contracting Services | $ | 180,656 | $ | 126,586 | $ | 54,070 | |||||
Shelf Contracting(1) | 227,398 | 222,530 | 4,868 | ||||||||
Oil and Gas | 120,861 | 162,386 | (41,525 | ) | |||||||
Intercompany elimination | (23,008 | ) | (8,024 | ) | (14,984 | ) | |||||
$ | 505,907 | $ | 503,478 | $ | 2,429 | ||||||
Gross Margin – | |||||||||||
Contracting Services | 27 | % | 28 | % | (1 | )pt | |||||
Shelf Contracting(1) | 36 | % | 44 | % | (8 | )pts | |||||
Oil and Gas | 21 | % | 38 | % | (17 | )pts | |||||
Total company | 29 | % | 38 | % | (9 | )pts | |||||
Number of vessels(2)/ Utilization(3) – | |||||||||||
Contracting Services: | |||||||||||
Pipelay | 6/79% | 4/87% | |||||||||
Well operations | 2/71% | 2/81% | |||||||||
ROVs | 39/78% | 31/76% | |||||||||
Shelf Contracting | 34/65% | 25/84% | |||||||||
1) | Represented by our consolidated, majority owned subsidiary, CDI. At December 31, 2007 and 2006, our ownership interest in CDI was approximately 58.5% and 73.0%, respectively. |
2) | Represents number of vessels as of the end the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party. |
3) | Average vessel utilization rate is calculated by dividing the total number of days the vessels in this category generated revenues by the total number of calendar days in the applicable period. |
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Intercompany segment revenues during the years ended December 31, 2007 and 2006 were as follows (in thousands):
Year Ended December 31, | Increase/ (Decrease) | |||||||||||
2007 | 2006 | |||||||||||
Contracting Services | $ | 115,864 | $ | 42,585 | $ | 73,279 | ||||||
Shelf Contracting | 33,702 | 15,261 | 18,441 | |||||||||
$ | 149,566 | $ | 57,846 | $ | 91,720 |
Intercompany segment profit (which only relates to intercompany capital projects) during the years ended December 31, 2007 and 2006 were as follows (in thousands):
Year Ended December 31, | Increase/ (Decrease) | |||||||||||
2007 | 2006 | |||||||||||
Contracting Services | $ | 10,026 | $ | 2,460 | $ | 7,566 | ||||||
Shelf Contracting | 12,982 | 5,564 | 7,418 | |||||||||
$ | 23,008 | $ | 8,024 | $ | 14,984 |
The following table details various financial and operational highlights related to our Oil and Gas segment for the periods presented (U.S. operations only as U.K. operations were immaterial for the periods presented):
Year Ended December 31, | Increase/ (Decrease) | |||||||||||
2007 | 2006 | |||||||||||
Oil and Gas information– | ||||||||||||
Oil production volume (MBbls) | 3,723 | 3,400 | 323 | |||||||||
Oil sales revenue (in thousands) | $ | 251,955 | $ | 205,415 | $ | 46,540 | ||||||
Average oil sales price per Bbl (excluding hedges) | $ | 70.17 | $ | 61.08 | $ | 9.09 | ||||||
Average realized oil price per Bbl (including hedges) | $ | 67.68 | $ | 60.41 | $ | 7.27 | ||||||
Increase in oil sales revenue due to: | ||||||||||||
Change in prices (in thousands) | $ | 24,699 | ||||||||||
Change in production volume (in thousands) | 21,841 | |||||||||||
Total increase in oil sales revenue (in thousands) | $ | 46,540 | ||||||||||
Gas production volume (MMcf) | 42,163 | 27,949 | 14,214 | |||||||||
Gas sales revenue (in thousands) | $ | 324,282 | $ | 219,674 | $ | 104,608 | ||||||
Average gas sales price per mcf (excluding hedges) | $ | 7.46 | $ | 7.46 | $ | ─ | ||||||
Average realized gas price per mcf (including hedges) | $ | 7.69 | $ | 7.86 | $ | (0.17 | ) | |||||
Increase (decrease) in gas sales revenue due to: | ||||||||||||
Change in prices (in thousands) | $ | (4,718 | ) | |||||||||
Change in production volume (in thousands) | 109,326 | |||||||||||
Total increase in gas sales revenue (in thousands) | $ | 104,608 | ||||||||||
Total production (MMcfe) | 64,500 | 48,349 | 16,151 | |||||||||
Price per Mcfe | $ | 8.93 | $ | 8.79 | $ | 0.14 | ||||||
Oil and Gas revenue information (in thousands)- | ||||||||||||
Oil and gas sales revenue | $ | 576,237 | $ | 425,089 | $ | 151,148 | ||||||
Miscellaneous revenues(1) | $ | 5,667 | $ | 4,518 | $ | 1,149 | ||||||
(1) | Miscellaneous revenues primarily relate to fees earned under our process handling agreements. |
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The following table highlights certain relevant expense items in total (in thousands) and on a cost per Mcfe of production basis:
Year Ended December 31, | ||||||||||||||||
2007 | 2006 | |||||||||||||||
Total | Per Mcfe | Total | Per Mcfe | |||||||||||||
Oil and gas operating expenses(1): | ||||||||||||||||
Direct operating expenses(2) | $ | 80,410 | $ | 1.25 | $ | 50,930 | $ | 1.05 | ||||||||
Workover | 11,840 | 0.18 | 11,462 | 0.24 | ||||||||||||
Transportation | 4,560 | 0.07 | 3,174 | 0.07 | ||||||||||||
Repairs and maintenance | 12,191 | 0.19 | 13,081 | 0.27 | ||||||||||||
Overhead and company labor | 9,031 | 0.14 | 10,492 | 0.22 | ||||||||||||
Total | $ | 118,032 | $ | 1.83 | $ | 89,139 | $ | 1.85 | ||||||||
Depletion and amortization | $ | 217,382 | $ | 3.37 | $ | 126,350 | $ | 2.61 | ||||||||
Abandonment | 21,073 | 0.33 | ─ | ─ | ||||||||||||
Accretion | 10,701 | 0.17 | 8,617 | 0.18 | ||||||||||||
Impairments | 64,072 | 0.99 | ─ | ─ | ||||||||||||
Total | $ | 313,228 | $ | 4.86 | $ | 134,967 | $ | 2.79 |
(1) | Excludes exploration expense of $26.7 million and $43.1 million for the years ended December 31, 2007 and 2006, respectively. Exploration expense is not a component of lease operating expense. |
(2) | Includes production taxes. |
Revenues. During the year ended December 31, 2007, our revenues increased by 30% as compared to 2006. Contracting Services revenues increased primarily due to improved contract pricing for the pipelay, well operations and ROV divisions. Shelf Contracting revenues increased primarily as a result of the initial deployment of certain assets we acquired through the Torch, Acergy and Fraser acquisitions that came into service subsequent to the first quarter of 2006 as well as the Horizon assets acquired in late 2007. These increases were partially offset by two vessels CDI did not operate (one owned and one chartered) in 2007 that were in operation in 2006 and an increased number of out-of-service days for regulatory drydock and vessel upgrades for certain vessels in our Shelf Contracting segment.
Oil and Gas revenues increased 36% during 2007 as compared to the prior year. The increase was primarily due to increases in oil and natural gas production. The production volume increase of 33% over 2006 was mainly attributable to properties acquired in connection with the Remington acquisition, which closed on July 1, 2006.
Gross Profit. The Contracting Services gross profit increase was primarily attributable to improved contract pricing for the pipelay, well operations and ROV divisions. The gross profit increase within Shelf Contracting was primarily attributable to increased gross profit derived from the initial deployment of certain assets we acquired subsequent to the first quarter 2006, offset by increased out-of-service days referred to above, lower vessel utilization as a result of seasonal weather in the fourth quarter 2007, and increased depreciation and deferred drydock amortization.
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The Oil and Gas gross profit decrease in 2007 as compared to 2006 was primarily due to the following factors:
• | impairment expenses totaling $64.1 million, which primarily reflected $59.4 million associated with property impairments related to downward reserve revisions and weak end of life well performance in some of our domestic properties and $9.6 million of increased future abandonment costs related to properties damaged by Katrina and Rita partially offset by estimated insurance recoveries of $4.9 million; | ||
• | an increase of $91.0 million in depletion expense in 2007 because of higher overall production based on a full year of activity from the Remington acquisition as compared to only half a year of impact in 2006 including approximately $12.5 million of increased fourth quarter 2007 depletion due to certain producing properties experiencing significant proved reserve declines; | ||
• | approximately $25.1 million of plug and abandonment overruns related to properties damaged by the hurricanes, partially offset by insurance recoveries of $4.0 million; | ||
• | approximately $9.9 million of impairment expense related to our unproved properties primarily due to management’s assessment that exploration activities for certain properties will not commence prior to the respective lease expiration dates; | ||
• | the gross profit decrease was partially offset by lower dry hole exploration expense in 2007 of $10.3 million, of which $5.9 million was related to our South Marsh Island 123 #1 well, as compared to $38.3 million dry hole expense in 2006 related to the Tulane prospect and two deep shelf wells commenced by Remington prior to the acquisition. |
Gain on Sale of Assets, Net. Gain on sale of assets, net, increased by $47.6 million during 2007 as compared to 2006. On September 30, 2007, we sold a 30% working interest in the Phoenix oilfield (Green Canyon Blocks 236/237), the Boris oilfield (Green Canyon Block 282) and the Little Burn oilfield (Green Canyon Block 238) to Sojitz for a cash payment of $51.2 million and recognized a gain of $40.4 million in 2007. We also recognized the following gains in 2007:
• | $2.4 million related to the sale of a mobile offshore production unit; | ||
• | $1.6 million related to the sale or 50% interest in Camelot; and | ||
• | $3.9 million related to the sale of assets owned by CDI. |
Selling and Administrative Expenses. Selling and administrative expenses of $145.0 million in 2007 were $30.8 million higher than the $114.2 million incurred in 2006. The increase was due primarily to higher overhead to support our growth and increased incentive compensation accruals. Further, in June 2007, CDI recorded a $2.0 million charge for a cash settlement with the Department of Justice. Selling and administrative expenses as a percent of revenues were approximately 8.4% in 2007 and 8.6% in 2006.
Equity in Earnings of Investments, Net of Impairment Charge. Equity in earnings of investments increased by $1.6 million during 2007 as compared to 2006. Equity in earnings related to our 20% investment in Independence Hub increased $10.5 million as we reached mechanical completion in March 2007 and began receiving demand fees and tariffs as production began in the third quarter. In addition, equity in earnings of our 50% investment in Deepwater Gateway increased by $2.2 million in 2007 as compared to 2006 due to higher throughput at the Marco Polo TLP. These increases were offset by second quarter 2007 equity losses from CDI’s 40% investment in OTSL and a related non-cash asset impairment charge together totaling $11.8 million.
Gain on Subsidiary Equity Transaction. We recognized a non cash pre-tax gain of $151.7 million ($98.6 million net of taxes of $53.1 million) in 2007 as our share of CDI’s underlying equity increased as a result of CDI’s issuance of 20.3 million shares of its common stock to former Horizon stockholders in connection with CDI’s acquisition of Horizon, which reduced our ownership in CDI to 58.5%. The non-cash gain is derived from the difference in the
14
value of our investment in CDI immediately before and after the acquisition. In 2006, CDI received net proceeds of $264.4 million from the initial public offering of 22.2 million shares of its common stock. Together with CDI’s drawdown of its revolving credit facility, CDI paid pre-tax dividends of $464.4 million to us in December 2006. As a result of these transactions, we recorded a pre-tax gain of $223.1 million ($96.5 million net of taxes of $126.6 million) in 2006.
Net Interest Expense and Other. We reported net interest and other expense of $67.0 million in 2007 as compared to $41.6 million in the prior year. Gross interest expense of $107.8 million during 2007 was higher than the $58.8 million incurred in 2006 as a result of our Term Loan and Revolving Loans, which closed in July 2006, and CDI’s revolving credit facility, which closed in December 2006. Offsetting the increase in interest expense was $31.8 million of capitalized interest and $9.2 million of interest income in 2007, compared with $10.6 million of capitalized interest and $6.3 million of interest income in 2006.
Provision for Income Taxes. Income taxes from continuing operations decreased to $171.9 million in 2007 compared to $252.8 million in 2006. This variance includes a $126.6 million decrease of the income tax expense related to the CDI dividends paid to us in 2006, which was partially offset by increased profitability in 2007. The effective tax rate of 33.3% for 2007 was lower than the 42.7% effective tax rate for 2006 due primarily to the CDI dividends of $464.4 million received in December 2006.
Liquidity and Capital Resources
Overview
The following tables present certain information useful in the analysis of our financial condition and liquidity for the periods presented (in thousands):
2008 | 2007 | |||||||
Net working capital | $ | 287,225 | $ | 48,290 | ||||
Long-term debt(1) | $ | 1,933,686 | $ | 1,683,340 |
(1) | Long-term debt does not include current maturities portion of the long-term debt as amount is included in net working capital. |
The carrying amount of our debt, including current maturities as of December 31, 2008 and 2007 follow (amount in thousands):
2008 | 2007 | |||||||
Term Loan (matures July 2013) | $ | 419,093 | $ | 423,418 | ||||
Revolving Credit Facility (matures July 2011) | 349,500 | 18,000 | ||||||
Cal Dive Term Loan (matures December 2012) | 315,000 | 375,000 | ||||||
Convertible Senior Notes (matures March 2025) (1) | 265,184 | 257,799 | ||||||
Senior Unsecured Notes (matures January 2016) | 550,000 | 550,000 | ||||||
MARAD Debt (matures August 2027) | 123,449 | 127,463 | ||||||
Loan Notes(2) | 5,000 | 6,506 | ||||||
Total | $ | 2,027,226 | $ | 1,758,186 | ||||
(1) | Net of the unamortized debt discount resulting from adoption of FSP APB 14-1 on January 1, 2009. The notes will increase to $300 million face amount through accretion of non-cash interest charges through 2012. |
(2) | Assumed to be current, represents the $5 million loan provided by Kommandor RØMØ to Kommandor LLC (Note 10). |
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Net cash provided by (used in): | ||||||||||||
Operating activities | $ | 437,719 | $ | 416,326 | $ | 514,036 | ||||||
Investing activities | $ | (557,974 | ) | $ | (739,654 | ) | $ | (1,379,930 | ) | |||
Financing activities | $ | 256,216 | $ | 206,445 | $ | 978,260 |
Our current requirements for cash primarily reflect the need to fund capital expenditures to allow the growth of our current lines of business and to service our existing debt. We also intend to repay debt with any additional free cash flow from operations and/or cash received from any dispositions of our non core business assets. Historically, we have funded our capital program, including acquisitions, with cash flow from operations, borrowings under credit facilities and use of project financing along with other debt and equity alternatives.
We are closely monitoring the relatively recent and ongoing volatility and uncertainty in the financial markets and have intensified our internal focus on liquidity, planned spending and access to capital. Externally we have also been engaged with our clients and the lending institutions on our various debt facilities as our customers and lenders are going through similar exercises. While we believe at this stage it is premature to accurately predict to what extent these current events may affect our overall activity levels in 2009 and beyond, we do expect a significant decrease in activity as compared to 2008. To date, we have received no communication from our lenders that they are unable or unwilling to fund any commitments under our Revolving Credit Facility. Additionally, all participating banks party to our Revolving Credit Facilities have honored their commitments. We also have a reasonable basis for estimating our future cash flow supported by our contracting services backlog and the significant hedged portion of our estimated 2009 oil and gas production. We believe that internally generated cash flow and available borrowing capacity under our existing Revolving Credit Facility will be sufficient to fund our operations for 2009.
A continuing period of weak economic activity will make it increasingly difficult to comply with our covenants and other restrictions in agreements governing our debt. Our ability to comply with these covenants and other restrictions is affected by the current economic conditions and other events beyond our control. If we fail to comply with these covenants and other restrictions, it could lead to an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by the lenders, including foreclosure on our pledged collateral. We cannot assure you that we would have access to the credit markets as needed to replace our existing debt and we could incur increased costs associated with any available replacement financing.
Some of the significant financings and corresponding uses were as follows:
• | In January 2009, CDI borrowed $100 million under our revolving credit facility to repurchase 13.6 million shares of its common stock from us for $6.34 per share. The remaining funds will be used to fund CDI working capital requirements and other general corporate purposes. As of February 20, 2009, CDI had $415 million of debt, $67.3 million of cash on hand and $186.7 million of available under our credit facility. | ||
• | In July 2007, we purchased the remaining 42% of WOSEA for $10.1 million. We now own 100% of this company (see “Note 6 — Other Acquisitions” in Item 8. Financial Statements and Supplementary Data for a detailed discussion of WOSEA). | ||
• | In December 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (“Senior Unsecured Notes”). Proceeds from the offering were used to repay outstanding indebtedness under our senior secured credit facilities. For additional information on the terms of the Senior Unsecured Notes, see “Note 11 — Long-term Debt” in Item 8. Financial Statements and Supplementary Data. | ||
• | Also in December 2007, CDI replaced its five-year $250 million revolving credit facility with a secured credit facility consisting of a $375 million term loan and a $300 million revolving credit facility. Proceeds from the CDI term loan were used to fund the cash portion of the Horizon acquisition. CDI expects to use the remaining capacity under the revolving credit facility for its working capital and other general corporate purposes. We do not have access to the unused portion of CDI’s revolving credit facility. See Note 11 for additional information regarding our long term debt. | ||
• | In July 2006, we borrowed $835 million in a term loan (“Term Loan”) and entered into a new $300 million revolving credit facility (Note 11). The proceeds of the Term Loan were used to fund the cash portion of the acquisition of Remington. We also issued approximately 13.0 million shares of our common stock to the Remington shareholders. | ||
• | In December 2006, we completed an IPO of our Shelf Contracting business segment (Cal Dive International, Inc.), selling 26.5% of that company and receiving pre-tax net proceeds of $264.4 million. We may sell additional shares of CDI common stock in the future. Proceeds from the offering were used for general corporate purposes, including the repayment of $71.0 million of borrowing under our Revolving Credit Facility (Note 3). | ||
• | In connection with the IPO, CDI Vessel Holdings LLC (“CDI Vessel”), a subsidiary of CDI, entered into a secured credit facility for up to $250 million in revolving loans under a five-year revolving credit facility. During December 2006, CDI Vessel borrowed $201 million under the revolving credit facility and distributed $200 million of those proceeds to us as a dividend. This revolving loan was replaced in December 2007 by the $300 million revolving credit facility described above. | ||
• | In October 2006, we initially invested $15 million for a 50% interest in Kommandor LLC, a Delaware limited liability company, to convert a ferry vessel into a dynamically-positioned minimal floating production system. We have consolidated the results of Kommandor LLC in accordance with FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities (“FIN 46”). For additional information, see Note 10. We have named the vessel Helix Producer I. | ||
• | Also in October 2006, we acquired the original 58% interest in WOSEA for total consideration of approximately $12.7 million (including $180,000 of transaction costs), with approximately $9.1 million paid to existing shareholders and $3.4 million for subscription of new WOSEA shares (see Note 6 for a detailed discussion of WOSEA). | ||
• | In 2006, our Board of Directors also authorized us to discretionarily purchase up to $50 million of our common stock in the open market. In October and November 2006, we purchased approximately 1.7 million shares under this program for a weighted average price of $29.86 per share, or $50.0 million. |
In accordance with our Senior Credit Facilities, Senior Unsecured Notes, the Convertible Senior Notes, the MARAD debt and Cal Dive’s credit facilities, we are required to comply with certain covenants and restrictions, including certain financial ratios such as collateral coverage, interest coverage, consolidated leverage, the maintenance of minimum net worth, working capital and debt-to-equity requirements. As of December 31, 2008, we were in compliance with these covenants. The Senior Credit Facilities and Senior Unsecured Notes also contain provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by the Company. The Senior Credit Facilities do permit us to incur certain unsecured indebtedness, and also provide for our subsidiaries to incur project financing indebtedness (such as our MARAD loans) secured by the underlying asset, provided that the indebtedness is not guaranteed by us. Upon the occurrence of certain dispositions or the issuance or incurrence of certain types of indebtedness, we may be required to prepay a portion of the Term Loan equal to the amount of proceeds received from such occurrences. Such prepayments will be applied first to the Term Loan, and any excess will then be applied to the Revolving Loans.
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As of December 31, 2008, we had $44.4 million ($59.4 million as of February 27, 2009) of available borrowing capacity under our Revolving Credit Facility, and CDI had $292.5 million of available borrowing capacity under its revolving credit facility. See Note 11 for additional information related to our long-term debts, including our obligations under capital commitments.
Working Capital
Net cash flows from operating activities increased $21.4 million in 2008 as compared to 2007 primarily reflecting significantly lower income taxes paid and increased gross profit from Contracting Services and Shelf Contracting businesses. These increases were partially offset by lower operating results for our Oil and Gas business reflecting the effects of Hurricanes Gustav and Ike had on its production during the third and fourth quarters of 2008 as well as our increased funding of our working capital requirements.
Net cash flow from operating activities decreased $97.7 million in 2007 as compared to 2006 primarily due to negative working capital changes in 2007. Compared to 2006, increased expenditures in other noncurrent assets, net, consisted of an additional $21.6 million in drydock expenses (net of amortization), $8.8 million for an equipment deposit and $14.6 million related to a non-current contract receivable for retainage. Working capital, net of cash, decreased approximately $145.5 million in 2007 when compared to 2006. Cash from operating activities was negatively impacted by higher income taxes paid in 2007 versus 2006 of approximately $146.9 million, of which $126.6 million was related to CDI’s initial public offering. These decreases were partially offset by increase in profitability, excluding the impact of non-cash related items, in 2007 as compared to 2006.
Investing Activities
Capital expenditures have consisted principally of the purchase or construction of DP vessels, acquisition of select businesses, improvements to existing vessels, acquisition of oil and gas properties and investments in our Production Facilities. Significant sources (uses) of cash associated with investing activities for the years ended December 31, 2008, 2008 and 2007 were as follows (in thousands):
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Capital expenditures: | ||||||||||||
Contracting services | $ | (258,184 | ) | $ | (286,362 | ) | $ | (129,847 | ) | |||
Shelf contracting | (83,108 | ) | (30,301 | ) | (38,086 | ) | ||||||
Oil and gas | (404,308 | ) | (519,632 | ) | (282,318 | ) | ||||||
Production facilities | (109,454 | ) | (106,086 | ) | (17,749 | ) | ||||||
Acquisition of businesses, net of cash acquired: | ||||||||||||
Remington Oil and Gas Corporation(1) | ─ | ─ | (772,244 | ) | ||||||||
Horizon Offshore Inc. (2) | ─ | (137,431 | ) | ─ | ||||||||
Acergy US Inc. (3) | ─ | ─ | (78,174 | ) | ||||||||
Fraser Diving International Ltd. (3) | ─ | ─ | (21,954 | ) | ||||||||
WOSEA(4) | ─ | (10,067 | ) | (10,571 | ) | |||||||
Kommandor LLC | ─ | ─ | (5,000 | ) | ||||||||
(Purchases) sale of short-term investments | ─ | 285,395 | (285,395 | ) | ||||||||
Investments in production facilities | (846 | ) | (17,459 | ) | (27,578 | ) | ||||||
Distributions from equity investments, net(4) | 11,586 | 6,679 | ─ | |||||||||
Increase in restricted cash | (614 | ) | (1,112 | ) | (6,666 | ) | ||||||
Proceeds from insurance | 13,200 | �� | ─ | ─ | ||||||||
Proceeds from sale of subsidiary stock | ─ | ─ | 264,401 | |||||||||
Proceeds from sale of properties (5) | 274,230 | 78,073 | 32,342 | |||||||||
Other, net | ─ | (136 | ) | ─ | ||||||||
Net cash used in investing activities | (557,498 | ) | (738,439 | ) | (1,378,839 | ) | ||||||
Net cash used in discontinued operations | (476 | ) | (1,215 | ) | (1,091 | ) | ||||||
Net cash used in investing activities | $ | (557,974 | ) | $ | (739,654 | ) | $ | (1,379,930 | ) |
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(1) | For additional information related to the Remington acquisition, see Note 4. |
(2) | For additional information related to the Horizon acquisition, see Note 5. |
(3) | For additional information related to these acquisitions, see Note 6. |
(4) | Distributions from equity investments is net of undistributed equity earnings from our investments. Gross distributions from our equity investments are detailed in Note 9. |
(5) | For additional information related to sales of properties, see Note 7. |
Short-term Investments
As of December 31, 2006, we held approximately $285.4 million in municipal auction rate securities. We did not hold these types of securities at December 31, 2008 or 2007. These instruments were long-term variable rate bonds tied to short-term interest rates reset through a “Dutch Auction” process which occurred every 7 to 35 days and were classified as available-for-sale securities.
Restricted Cash
As of December 31, 2008 we had $35.4 million of restricted cash, included in other assets, net, in the accompanying consolidated balance sheet, all of which related to the escrow funds for decommissioning liabilities associated with the South Marsh Island Block 130 (“SMI 130”) acquisition in 2002. Under the purchase agreement for this property, we are obligated to escrow 50% of production up to the first $20 million and 37.5% of production on the remaining balance up to $33 million in total . We had fully escrowed the requirement as of December 31, 2008. We may use the restricted cash for decommissioning the related field.
Outlook
We anticipate capital expenditures in 2009 will range from $350 million to $400 million (of which $78 million is related to CDI). The estimates for these capital expenditures may increase or decrease based on various economic factors. However, we may reduce the level of our planned capital expenditures given a prolonged economic downturn and inability to execute sales transactions related to our non core business assets. We believe internally generated cash flow, cash from future sales of our non core business assets, and borrowings under our existing credit facilities will provide the capital necessary to fund our 2009 initiatives.
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual cash obligations as of December 31, 2008 and the scheduled years in which the obligation are contractually due (in thousands):
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Total (1) | Less Than 1 year | 1-3 Years | 3-5 Years | More Than 5 Years | ||||||||||||||||
Convertible Senior Notes(2) | $ | 300,000 | $ | ─ | $ | ─ | $ | ─ | $ | 300,000 | ||||||||||
Senior Unsecured Notes | 550,000 | ─ | ─ | ─ | 550,000 | |||||||||||||||
Term Loan | 419,093 | 4,326 | 8,652 | 406,115 | ─ | |||||||||||||||
Revolving Loans | 349,500 | ─ | 349,500 | ─ | ─ | |||||||||||||||
MARAD debt | 123,449 | 4,214 | 9,069 | 9,997 | 100,169 | |||||||||||||||
CDI Term Loan | 315,000 | 80,000 | 160,000 | 75,000 | ─ | |||||||||||||||
Loan note | 5,000 | 5,000 | ─ | ─ | ─ | |||||||||||||||
Interest related to long-term debt(3) | 693,364 | 101,093 | 178,169 | 158,881 | 255,221 | |||||||||||||||
Preferred stock dividends(4) | 1,000 | 1,000 | ─ | ─ | ─ | |||||||||||||||
Drilling and development costs | 106,300 | 16,800 | 89,500 | ─ | ─ | |||||||||||||||
Property and equipment(5) | 47,941 | 47,941 | ─ | ─ | ─ | |||||||||||||||
Operating leases(6) | 191,623 | 84,893 | 75,708 | 21,644 | 9,378 | |||||||||||||||
Total cash obligations | $ | 3,102,270 | $ | 345,267 | $ | 870,598 | $ | 671,637 | $ | 1,214,768 |
(1) | Excludes unsecured letters of credit outstanding at December 31, 2008 totaling $33.7 million. These letters of credit primarily guarantee various contract bidding, insurance activities and shipyard commitments. |
(2) | Contractual maturity in 2025 (Notes can be redeemed by us or we may be required to purchase beginning in December 2012). Can be converted prior to stated maturity if closing sale price of Helix’s common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 120% of the closing price on that 30th trading day (i.e. $38.56 per share) and under certain triggering events as specified in the indenture governing the Convertible Senior Notes. To the extent we do not have alternative long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet. As of December 31, 2008, the conversion trigger was not met. |
(3) | Includes total interest obligations of $26.4 million related to CDI’s long-term debt. |
(4) | Amount represents dividend payment for 2009 only. Dividends are paid annually until such time the holder elects to convert or redeem the stock. The holder redeemed $30 million of our convertible preferred stock shares into 5.9 million shares of our common stock in January 2009 (Note 13). Our first-quarter 2009 results will include a corresponding noncash dividend of $29.3 million to reflect the redemption of the incremental shares issued to the holder above the shares underlying the redemption feature. This dividend will reduce the net income available to our common shareholders for the period. |
(5) | Costs incurred as of December 31, 2008 and additional property and equipment commitments (excluding capitalized interest) at December 31, 2008 consisted of the following (in thousands): |
Costs Incurred | Costs Committed | Total Project Cost | ||||||||||
Caesar conversion | $ | 158,937 | $ | 11,832 | $ | 210,000—230,000 | ||||||
Well Enhancer construction | 149,691 | 31,165 | 200,000—220,000 | |||||||||
Helix Producer I conversion(a) | 210,107 | 4,944 | 345,000—365,000 | |||||||||
Total | $ | 518,735 | $ | 47,941 | $ | 755,000—815,000 |
(a) Represents 100% of the vessel conversion cost, of which we expect our portion to range between $301 million and $321 million.
(6) | Operating leases included facility leases and vessel charter leases. Vessel charter lease commitments at December 31, 2008 were approximately $153.9 million. Operating leases include $21.6 million related to CDI. |
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Contingencies
In December 2005 and in May 2006, our Oil and Gas segment received notice from the MMS that the price threshold was exceeded for 2004 oil and gas production and for 2003 gas production, respectively, and that royalties are due on such production notwithstanding the provisions of the DWRRA. In addition, in September 2008, we received notice from the MMS that price thresholds were exceeded for 2007, 2006 and 2005 oil and gas production. The total reserved amount at December 31, 2008 was approximately $69.7 million and was included in Other Long Term Liabilities in the accompanying consolidated balance sheet included herein. On January 12, 2009, the United States Court of Appeals for the Fifth Circuit affirmed the decision of the district court in favor of Kerr-McGee, holding that the DWRRA unambiguously provides that royalty suspensions up to certain production volumes established by Congress apply to leases that qualify under the DWRRA. As a result of this ruling, we believe that any future payment of these contractual royalties is not probable. Accordingly, in the first quarter of 2009 our operating results will include a $69.7 million gain from the reversal of these previously reserves amounts associated with the potential payment of the disputed royalties. See Item 3. Legal Proceedings and Note 18 for a detailed discussion of this contingency.
Convertible Preferred Stock
In January 2003, we completed the private placement of $25 million of a newly designated class of cumulative convertible stock (Series A-1 Cumulative Convertible Stock, par value $0.01 per share) convertible into 1,666,668 shares or our common stock at $15 per share. The preferred stock was issued to a private investment firm, Fletcher International, Ltd.(“Fletcher”). Subsequently on June 2004, Fletcher exercised an existing right to purchase an additional $30 million of cumulative convertible preferred stock (Series A-2 Cumulative Convertible Preferred Stock, par value $0.01 per share) convertible into 1,964,058 shares of our common stock at $15.27 per share. Pursuant to the agreement governing the preferred stock (the “Fletcher Agreement”), Fletcher was entitled to convert its investment in the preferred shares at any time, and to redeem its investment in the preferred shares at any time after December 31, 2004. In January 2009, Fletcher issued a redemption notice with respect to all of the Series A-2 Cumulative Convertible Preferred Stock, and, pursuant to such redemption, we issued and delivered 5,938,776 shares of our common stock to Fletcher. We will reduce net income applicable to common shareholders by an approximate $29.3 million non-cash dividend that will be reflected in our first quarter of 2009 results. This non-cash dividend reflects the value associated with the additional 3,974,718 shares delivered over the original 1,964,058 shares that were contractually required to be issued upon a conversion.
The Fletcher Agreement provides that if the volume weighted average price of our common stock on any date is less than a certain minimum price ($2.767), then our right to pay dividends in our common stock is extinguished, and we must deliver a notice to Fletcher that either (1) the conversion price will be reset to such minimum price (in which case Fletcher shall have no further right to cause the redemption of the preferred stock), or (2) in the event Fletcher exercises its redemption rights, we will satisfy our redemption obligations either in cash, or a combination of cash and common stock subject to a maximum number of shares (14,973,814) that can be delivered to the holder under the Fletcher Agreement. As a result of the redemption that occurred in January, the maximum number of shares available for redemption of Series A-1 Cumulative Convertible Stock is 9,035,038. On February 25, 2009 the volume weighted average price of our common stock was below the minimum price, and on February 27, 2009 we provided notice to Fletcher that with respect to the Series A-1 Cumulative Convertible Preferred Stock the conversion price is reset to $2.767 as of that date and that Fletcher shall have no further rights to redeem the shares, and we have no further right to pay dividends in common stock. As a result of Fletcher’s redemption in January 2009, and the reset of the conversion price, Fletcher would receive an aggregate of 9,035,038 shares in future conversion(s) into our common stock. In the event we elect to settle any future conversion in cash, Fletcher would receive cash in an amount
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approximately equal to the value of the shares it would receive upon a conversion, which could be substantially greater than the original face amount of the Series A-1 Cumulative Convertible Preferred Stock. Under the existing terms of our Senior Credit Facilities (Note 11) we are not permitted to deliver cash to the holder upon a conversion of the Convertible Preferred Stock.
Critical Accounting Estimates and Policies
Our results of operations and financial condition, as reflected in the accompanying financial statements and related footnotes, are prepared in conformity with accounting principles generally accepted in the United States. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We believe the most critical accounting policies in this regard are those described below. While these issues require us to make judgments that are somewhat subjective, they are generally based on a significant amount of historical data and current market data. For a detailed discussion on the application of our accounting policies, see Item 8. Financial Statements and Supplementary Data “— Notes to Consolidated Financial Statements — Note 2.”
Revenue Recognition
Contracting Services Revenues
Revenues from Contracting Services and Shelf Contracting are derived from contracts that traditionally have been of relatively short duration; however, beginning in 2007, contract durations started to become longer-term. These contracts contain either lump-sum turnkey provisions or provisions for specific time, material and equipment charges, which are billed in accordance with the terms of such contracts. We recognize revenue as it is earned at estimated collectible amounts. Further, we record revenue net of taxes collected from customers and remitted to governmental authorities.
Unbilled revenue represents revenue attributable to work completed prior to period end that has not yet been invoiced. All amounts included in unbilled revenue at December 31, 2008 and 2007 are expected to be billed and collected within one year.
Dayrate Contracts. Revenues generated from specific time, materials and equipment contracts are generally earned on a dayrate basis and recognized as amounts are earned in accordance with contract terms. In connection with these contracts, we may receive revenues for mobilization of equipment and personnel. In connection with new contracts, revenues related to mobilization are deferred and recognized over the period in which contracted services are performed using the straight-line method. Incremental costs incurred directly for mobilization of equipment and personnel to the contracted site, which typically consist of materials, supplies and transit costs, are also deferred and recognized over the period in which contracted services are performed using the straight-line method. Our policy to amortize the revenues and costs related to mobilization on a straight-line basis over the estimated contract service period is consistent with the general pace of activity, level of services being provided and dayrates being earned over the service period of the contract. Mobilization costs to move vessels when a contract does not exist are expensed as incurred.
Turnkey Contracts. Revenue on significant turnkey contracts is recognized on the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. In determining whether a contract should be accounted for using the percentage-of-completion method, we consider whether:
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• | the customer provides specifications for the construction of facilities or for the provision of related services; | ||
• | we can reasonably estimate our progress towards completion and our costs; | ||
• | the contract includes provisions as to the enforceable rights regarding the goods or services to be provided, consideration to be received and the manner and terms of payment; | ||
• | the customer can be expected to satisfy its obligations under the contract; and | ||
• | we can be expected to perform our contractual obligations. |
Under the percentage-of-completion method, we recognize estimated contract revenue based on costs incurred to date as a percentage of total estimated costs. Changes in the expected cost of materials and labor, productivity, scheduling and other factors affect the total estimated costs. Additionally, external factors, including weather and other factors outside of our control, may also affect the progress and estimated cost of a project’s completion and, therefore, the timing of income and revenue recognition. We routinely review estimates related to our contracts and reflect revisions to profitability in earnings on a current basis. If a current estimate of total contract cost indicates an ultimate loss on a contract, we recognize the projected loss in full when it is first determined. At December 31, 2008, we had two contracts that were deemed to be in loss status and we recorded an aggregate $9.8 million charge to cost of sales to estimate the expected loss to completion of the respective contracts (Note 2). We recognize additional contract revenue related to claims when the claim is probable and legally enforceable.
Oil and Gas Revenues
We record revenues from the sales of crude oil and natural gas when delivery to the customer has occurred, prices are fixed and determinable, collection is reasonably assured and title has transferred. This occurs when production has been delivered to a pipeline or a barge lifting has occurred. We may have an interest with other producers in certain properties. In this case, we use the entitlements method to account for sales of production. Under the entitlements method, we may receive more or less than our entitled share of production. If we receive more than our entitled share of production, the imbalance is treated as a liability. If we receive less than our entitled share, the imbalance is recorded as an asset. As of December 31, 2008, the net imbalance was a $1.7 million asset and was included in Other Current Assets ($7.5 million) and Accrued Liabilities ($5.8 million) in the accompanying consolidated balance sheet.
Purchase Price Allocation
In connection with a purchase business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of purchase price over amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the value attributed to assets acquired and liabilities assumed.
In December 2007, CDI completed the acquisition of Horizon. This acquisition was accounted for as a business combination. The allocation of the purchase price was finalized during 2008 based upon valuations using estimates and assumptions that were reviewed and approved by CDI management.
In July 2006, we acquired the assets and assumed the liabilities of Remington in a transaction accounted for as a business combination. In estimating the fair values of Remington’s assets and liabilities, we made various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, we prepared estimates of crude oil and natural gas
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reserves. We estimated future prices to apply to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the merger. The market-based weighted average cost of capital rate was subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the estimated probable and possible reserves were reduced by additional risk-weighting factors.
Estimated deferred taxes were based on available information concerning the tax basis of Remington’s assets and liabilities and loss carryforwards at the merger date. The allocation of purchase price for Remington was finalized in 2007.
While the estimates of fair value for the assets acquired and liabilities assumed have no effect on our cash flows, they can have an effect on the future results of operations. Generally, higher fair values assigned to crude oil and natural gas properties result in higher future depreciation, depletion and amortization expense, which results in a decrease in future net earnings. Also, a higher fair value assigned to crude oil and natural gas properties, based on higher future estimates of crude oil and natural gas prices, could increase the likelihood of an impairment in the event of lower commodity prices or higher operating costs than those originally used to determine fair value. An impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.
In 2006, we also completed the acquisition of Acergy, Fraser and 58% of Seatrac. These acquisitions were accounted for as business combinations as well. We finalized the purchase price allocation for Acergy and Fraser in the second quarter of 2006 and 2007, respectively. In July 2007, we purchased the remaining 42% of Seatrac. The allocation of purchase price for Seatrac was finalized in 2008.
We complete our valuation of assets and liabilities (including deferred taxes) for the purpose of allocation of the total purchase price amount to assets acquired and liabilities assumed during the twelve-month period following the acquisition date.
For more information regarding the allocation of purchase price associated with our acquisition see Notes 4, 5 and 6.
Goodwill and Other Intangible Assets
Under Statement of Financial Accounting Standard No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), we are required to perform an annual impairment analysis of goodwill and intangible assets. We elected November 1 to be the annual impairment assessment date for goodwill and other intangible assets. However, we could be required to evaluate the recoverability of goodwill and other intangible assets prior to the required annual assessment date if we experience disruption to the business, unexpected significant declines in operating results, divestiture of a significant component of the business emergence of unanticipated competition, loss of key personnel or a sustained declined in market capitalization. SFAS No. 142 also requires testing of goodwill impairment to be at a reporting unit level and defines the reporting unit as an operating segment, as that term is used in SFAS No. 131, or one level below the operating segment (referred to as a “component”), depending on whether certain criteria are met. At the time of our annual assessment of goodwill, we had six reporting units with goodwill and our impairment analysis was conducted at this level.
Goodwill impairment is determined using a two-step process that requires management to make judgments in determining what assumptions to use in the calculation. The first step is to identify if a potential impairment exists by comparing the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to have a potential impairment and the
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second step of the impairment test is not necessary. However, if the carrying amount of a reporting unit exceeds its fair value, the second step is performed to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any.
The second step compares the implied fair value of goodwill with the carrying amount of goodwill. If the implied fair value of goodwill exceeds the carrying amount, then goodwill is not considered impaired. However, if the carrying amount of goodwill exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination (i.e. the fair value of the reporting unit is allocated to all the assets and liabilities, including any unrecognized intangible assets, as if the reporting unit had been acquired in a business combination).
We use both the income approach and market approach to estimate the fair value of our reporting units under the first step. Under the income approach, a discounted cash flow analysis is performed requiring us to make various judgmental assumptions about future revenue, operating margins, growth rates and discount rates. These judgmental assumptions are based on our budgets, long-term business plans, reserve reports, economic projections, anticipated future cash flows and market place data. Under the market approach, the fair value of each reporting unit is calculated by applying an average peer total invested capital EBITDA (defined as earnings before interest, income taxes and depreciation and amortization) multiple to the 2009 budgeted EBITDA for each reporting unit. Judgment is required when selecting peer companies that operate in the same or similar lines of business and are potentially subject to the same corresponding economic risks.
Based on the first step of the 2008 goodwill impairment analysis, the carrying amount of two of our reporting units exceeded its fair value as calculated under the first step, which required us to perform the second step of the impairment test. In the second step, the fair value of tangible and certain intangible assets was generally estimated using discounted cash flow analysis. The fair value of intangibles with indefinite lives, such as trademarks, was calculated using a royalty rate method. Based on our 2008 goodwill and indefinite-lived intangible impairment analysis, in the fourth quarter of 2008 we recorded a $704.3 million charge to write off the remaining goodwill of our Oil and Gas segment. The impairment charges associated with our oil and gas segment are recorded as a component of operating loss in the accompanying consolidated statements of operations. We also recorded a $10.7 million charge in the fourth quarter of 2008 to write off the remaining goodwill and indefinite-lived intangible assets associated with our acquisition of Helix Energy Limited in 2005. Those impairment charges are reflected as components of income (loss) from discontinued operations in the accompanying consolidated statements of operations included in Exhibit 99.3 of this Current Report on Form 8-K as a result of our sale of Helix Energy Limited in April 2009. These impairment charges did not have any current effect and will not have any future effect on cash flow or our results of operations.
While we believe we have made reasonable estimates and assumptions to calculate the fair value of the reporting units and other intangible assets, it is possible a material change could occur. We have $366.2 million of goodwill remaining at December 31, 2008, including $292.5 million for CDI. If our actual results are not consistent with our estimates and assumptions used to calculate fair value, our results of operations may be materially impacted as further impairments may occur. Unless there is a dramatic improvement in prevailing economic conditions, we will be required to again assess the fair value of our remaining goodwill and other intangible assets at March 31, 2009.
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Income Taxes
Deferred income taxes are based on the difference between financial reporting and tax bases of assets and liabilities. We utilize the liability method of computing deferred income taxes. The liability method is based on the amount of current and future taxes payable using tax rates and laws in effect at the balance sheet date. Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.
We consider the undistributed earnings of our principal non-U.S. subsidiaries to be permanently reinvested. At December 31, 2008, our principal non-U.S. subsidiaries had accumulated earnings and profits of approximately $127.8 million. We have not provided deferred U.S. income tax on the accumulated earnings and profits. The deconsolidation of CDI’s net income for tax return filing purposes after its initial public offering did not have a material impact on our consolidated results of operations; however, because of our inability to recover our tax basis in CDI tax free, a long term deferred tax liability is provided for any incremental increases to the book over tax basis.
It is our policy to provide for uncertain tax positions and the related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities. At December 31, 2008, we believe we have appropriately accounted for any unrecognized tax benefits. To the extent we prevail in matters for which a liability for an unrecognized tax benefit is established or are required to pay amounts in excess of the liability, our effective tax rate in a given financial statement period may be affected.
See Note 12 for discussion of net operating loss carry forwards, deferred income taxes and uncertain tax positions taken by the Company.
Accounting for Oil and Gas Properties
Acquisitions of producing offshore properties are recorded at the fair value exchanged at closing together with an estimate of their proportionate share of the decommissioning liability assumed in the purchase (based upon their working interest ownership percentage). In estimating the decommissioning liability assumed in offshore property acquisitions, we perform detailed estimating procedures, including engineering studies and then reflect the liability at fair value on a discounted basis as discussed below.
We follow the successful efforts method of accounting for our interests in oil and gas properties. Under the successful efforts method, the costs of successful wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Capitalized costs of producing oil and gas properties are depleted to operations by the unit-of-production method based on proved developed oil and gas reserves on a field-by-field basis as determined by our engineers. Leasehold costs for producing properties are depleted using the units-of-production method based on the amount of total estimated proved reserves on a field-by-field basis. Costs incurred relating to unsuccessful exploratory wells are expensed in the period the drilling is determined to be unsuccessful (see “— Exploratory Drilling Costs” below).
We evaluate the impairment of our proved oil and gas properties on a field-by-field basis at least annually or whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If an impairment is indicated, the cash flows are discounted at a rate approximate to our cost of capital and compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil and natural gas reserves and future commodity prices, operating costs and future capital expenditures. Downward revisions in estimates of proved reserve quantities or expectations of falling
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commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment. We recorded property impairments totaling $215.7 million in 2008 ($192.6 million in the fourth quarter of 2008) and approximately $64.1 million of property impairments in 2007, primarily related to downward reserve revisions and weak end of life well performance in some of our domestic properties. There was no impairment of proved oil and gas properties in 2006.
We also periodically assess unproved properties for impairment based on exploration and drilling efforts to date on the individual prospects and lease expiration dates. Management’s assessment of the results of exploration activities, availability of funds for future activities and the current and projected political climate in areas in which we operate also impact the amounts and timing of impairment provisions. We recorded a total of $8.9 million of exploration expense to write off certain unproved oil and gas properties reflecting management’s assessment that exploration activities will not commence prior to the respective lease expiration dates, including a $8.0 million charge in the fourth quarter of 2008. During 2007, we recorded $9.9 million of exploration expense to impair certain unproved leasehold costs. There were no asset impairments recorded in 2006.
Exploratory Drilling Costs
In accordance with the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized as uncompleted or “suspended” wells temporarily pending the determination of whether the well has found proved reserves. If proved reserves are not found, these capitalized costs are charged to expense. A determination that proved reserves have been found results in the continued capitalization of the drilling costs of the well and its reclassification as a well containing proved reserves.
At times, it may be determined that an exploratory well may have found hydrocarbons at the time drilling is completed, but it may not be possible to classify the reserves at that time. In this case, we may continue to capitalize the drilling costs as an uncompleted well beyond one year when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project, or the reserves are deemed to be proved. If reserves are not ultimately deemed proved or economically viable, the well is considered impaired and its costs, net of any salvage value, are charged to expense. At December 31, 2007, we had two wells that were deemed to be suspended wells under the criteria established by SFAS 19-1 “Accounting for Suspended Well Costs”. Following the significant decrease in commodity prices in the second half of 2008 coupled with the December 2008 announcement of our intention to sell all or a part of our oil and gas business, we determined that further development of these wells was not probable. Accordingly, we recorded a total of $18.8 million to exploration expense to fully write off the capital costs associated with these two suspended wells.
Occasionally, we may choose to salvage a portion of an unsuccessful exploratory well in order to continue exploratory drilling in an effort to reach the target geological structure/formation. In such cases, we charge only the unusable portion of the well bore to dry hole expense, and we continue to capitalize the costs associated with the salvageable portion of the well bore and add the costs to the new exploratory well. In certain situations, the well bore may be carried for more than one year beyond the date drilling in the original well bore was suspended. This may be due to the need to obtain, and/or analyze the availability of equipment or crews or other activities necessary to pursue the targeted reserves or evaluate new or reprocessed seismic and geographic data. If, after we analyze the new information and conclude that we will not reuse the well bore or if the new exploratory well is determined to be unsuccessful after we complete drilling, we will charge the capitalized costs to dry hole expense. During the years ended December 31, 2008, 2007 and 2006, we incurred $27.7 million, $20.2 million and $38.3 million, respectively, of exploratory expenses (Note 7).
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Estimated Proved Oil and Gas Reserves
The evaluation of our oil and gas reserves is critical to the management of our oil and gas operations. Decisions such as whether development of a property should proceed and what technical methods are available for development are based on an evaluation of reserves. These oil and gas reserve quantities are also used as the basis for calculating the unit-of-production rates for depreciation, depletion and amortization, evaluating impairment and estimating the life of our producing oil and gas properties in our decommissioning liabilities. Our proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves expected to be recovered from new wells from undrilled proven reservoirs or from existing wells where a significant major expenditure is required for completion and production. We prepare all of our reserve information, and our independent petroleum engineers’ audit, and the estimates of our oil and gas reserves presented in this report (U.S. reserves only) based on guidelines promulgated under generally accepted accounting principles in the United States. See detailed description of our use of the term “engineering audit” and our process of preparing reserve estimates in Item 2. Properties “— Summary of Natural Gas and Oil Reserve Data.” Our estimated proved reserves in this Annual Report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the estimated proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices, or production equipment/facility capacity.
Accounting for Decommissioning Liabilities
Our decommissioning liabilities consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) requires oil and gas companies to reflect decommissioning liabilities on the face of the balance sheet at fair value on a discounted basis. Prior to the Remington acquisition, we have historically purchased producing offshore oil and gas properties that are in the later stages of production. In conjunction with acquiring these properties, we assume an obligation associated with decommissioning the property in accordance with regulations set by government agencies. The abandonment liability related to the acquisitions of these properties is determined through a series of management estimates.
Prior to an acquisition and as part of evaluating the economics of an acquisition, we will estimate the plug and abandonment liability. Our oil and gas operations personnel prepare detailed cost estimates to plug and abandon wells and remove necessary equipment in accordance with regulatory guidelines. We currently calculate the discounted value of the abandonment liability (based on an estimate of the year the abandonment will occur) in accordance with SFAS No. 143 and capitalize that portion as part of the basis acquired and record the related abandonment liability at fair value. The recognition of a decommissioning liability requires that management make numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for liability; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Decommissioning liabilities were $225.8 million and $217.5 million at December 31, 2008 and 2007, respectively.
On an ongoing basis, our oil and gas operations personnel monitor the status of wells, and as fields deplete and no longer produce, our personnel will monitor the timing requirements set forth
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by the MMS for plugging and abandoning the wells and commence abandonment operations, when applicable. On an annual basis, management personnel reviews and updates the abandonment estimates and assumptions for changes, among other things, in market conditions, interest rates and historical experience. In 2008 and 2007, we incurred $16.0 million and $25.1 million of plug and abandonment overruns related to hurricanes Katrina and Rita, respectively, partially offset by insurance recoveries of $13.4 million and $4.0 million.
Derivative Instruments and Hedging Activities
Our price risk management activities involve the use of derivative financial instruments to hedge the impact of market price risk exposures primarily related to our oil and gas production, variable interest rate exposure and foreign currency exposure. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we have entered into certain derivative contracts, primarily collars and swaps, for a portion of our oil and gas production, interest rate swaps, and foreign currency forward contracts. Our oil and gas costless collars and swaps, interest rate swaps, and foreign currency forward exchange contracts are reflected in our balance sheet at fair value. Hedge accounting does not apply to our oil and gas forward sales contracts as these qualify for the normal purchase and sale scope exception under Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”).
We engage primarily in cash flow hedges. Changes in the derivative fair values that are designated as cash flow hedges are deferred to the extent that they are effective and are recorded as a component of accumulated other comprehensive income (a component of shareholders’ equity) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge’s change in value is recognized immediately in earnings.
We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. Changes in the assumptions used could impact whether the fair value change in the hedged instrument is charged to earnings or accumulated other comprehensive income.
The fair value of our oil and gas costless collars reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. The fair value of our interest rate swaps is calculated as the discounted cash flows of the difference between the rate fixed by the hedge instrument and the LIBOR forward curve over the remaining term of the hedge instrument. The fair value of our foreign currency forward exchange contract is calculated as the discounted cash flows of the difference between the fixed payment as specified by the hedge instrument and the expected cash inflow of the forecasted transaction using a foreign currency forward curve.
These modeling techniques require us to make estimates of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative.
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Property and Equipment
Property and equipment (excluding oil and gas properties and equipment), both owned and under capital leases, are recorded at cost. Depreciation is provided primarily on the straight-line method over the estimated useful lives of the assets (Note 2).
For long-lived assets to be held and used, excluding goodwill, we base our evaluation of recoverability on impairment indicators such as the nature of the assets, the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate that the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis of the asset at the lowest level for which identifiable cash flows exist. Our marine vessels are assessed on a vessel by vessel basis, while our ROVs are grouped and assessed by asset class. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on management’s estimate of discounted cash flows.
Assets are classified as held for sale when we have a formalized plan for disposal of certain assets and those assets meet the held for sale criteria. Assets held for sale are reviewed for potential loss on sale when the company commits to a plan to sell and thereafter while the asset is held for sale. Losses are measured as the difference between the fair value less costs to sell and the asset’s carrying value. Estimates of anticipated sales prices are judgmental and subject to revisions in future periods, although initial estimates are typically based on sales prices for similar assets and other valuation data. We had no assets that met the criteria of being classified as assets held for sale at December 31, 2008.
Recertification Costs and Deferred Drydock Charges
Our Contracting Services and Shelf Contracting vessels are required by regulation to be recertified after certain periods of time. These recertification costs are incurred while the vessel is in drydock. In addition, routine repairs and maintenance are performed and, at times, major replacements and improvements are performed. We expense routine repairs and maintenance as they are incurred. We defer and amortize drydock and related recertification costs over the length of time for which we expect to receive benefits from the drydock and related recertification, which is generally 30 months. Vessels are typically available to earn revenue for the 30-month period between drydock and related recertification processes. A drydock and related recertification process typically lasts one to two months, a period during which the vessel is not available to earn revenue. Major replacements and improvements, which extend the vessel’s economic useful life or functional operating capability, are capitalized and depreciated over the vessel’s remaining economic useful life. Inherent in this process are estimates we make regarding the specific cost incurred and the period that the incurred cost will benefit.
As of December 31, 2008 and 2007, capitalized deferred drydock charges (Note 8) totaled $38.6 million and $48.0 million, respectively. During the years ended December 31, 2008, 2007 and 2006, drydock amortization expense was $26.0 million, $23.0 million and $12.0 million, respectively. We expect drydock amortization expense to increase in future periods due to increases in the number of vessels as a result of the acquisitions made in 2006 and 2007.
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Equity Investments
We periodically review our investments in Deepwater Gateway and Independence Hub for impairment. Under the equity method of accounting, an impairment loss would be recorded whenever a decline in value of an equity investment below its carrying amount is determined to be other than temporary. In judging “other than temporary,” we would consider the length of time and extent to which the fair value of the investment has been less than the carrying amount of the equity investment, the near-term and longer-term operating and financial prospects of the equity company and our longer-term intent of retaining the investment in the entity. During 2007, CDI determined that there was an other than temporary impairment in OTSL and the full value of CDI’s investment in OTSL was impaired and CDI recognized equity losses of OTSL, inclusive of the impairment charge, of $10.8 million in 2007 (Note 9).
Worker’s Compensation Claims
Our onshore employees are covered by Worker’s Compensation. Offshore employees, including divers, tenders and marine crews, are covered by our Maritime Employers Liability insurance policy which covers Jones Act exposures. We incur worker’s compensation claims in the normal course of business, which management believes are substantially covered by insurance. Our insurers and legal counsel analyze each claim for potential exposure and estimate the ultimate liability of each claim. Actual liability can be materially different from our estimates and can have a direct impact on our liquidity and results of operations.
Recently Issued Accounting Principles
In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The FASB agreed to defer the effective date of SFAS No. 157 for all nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. We adopted the provisions of SFAS No. 157 on January 1, 2008 for assets and liabilities not subject to the deferral and adopted this standard for all other assets and liabilities on January 1, 2009. The adoption of SFAS No. 157 had immaterial impact on our results of operations, financial condition and liquidity.
SFAS No. 157, among other things, defines fair value, establishes a consistent framework for measuring fair value and expands disclosure for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. SFAS No. 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants. SFAS No. 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:
· | Level 1. Observable inputs such as quoted prices in active markets; |
· | Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and |
· | Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions. |
Assets and liabilities measured at fair value are based on one or more of three valuation techniques noted in SFAS No. 157. The valuation techniques are as follows:
(a) | Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. |
(b) | Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost). |
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(c) | Income Approach. Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models). |
The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at December 31, 2008 (in thousands):
Level 1 | Level 2 | Level 3 | Total | Valuation Technique | ||||||||||||||||
Assets: | ||||||||||||||||||||
Oil and gas swaps and collars | – | $ | 22,307 | – | $ | 22,307 | (c) | |||||||||||||
Liabilities: | ||||||||||||||||||||
Foreign currency forwards | – | 940 | – | 940 | (c) | |||||||||||||||
Interest rate swaps | – | 7,967 | – | 7,967 | (c) | |||||||||||||||
Total | – | $ | 8,907 | – | $ | 8,907 |
In December 2007, the FASB issued Statement No. 141 (Revised), Business Combinations (“SFAS No. 141(R)”). SFAS No. 141 (R) requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. It also requires that the costs incurred related to the acquisition be charged to expense as incurred, when previously these costs were capitalized as part of the acquisition cost of the assets or business. The provisions of SFAS No. 141(R) are effective for fiscal years beginning after December 15, 2008 and should be adopted prospectively. We adopted the provisions of SFAS No. 141(R) on January 1, 2009 and it had no impact on our results of operations, cash flows and financial condition.
In December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB 51 (“SFAS No. 160”). SFAS No. 160 improves the relevance, comparability, and transparency of financial information provided to investors by requiring all entities to report noncontrolling (minority) interests in subsidiaries as equity in the consolidated financial statements. We adopted SFAS No. 160 on January 1, 2009. The provisions of SFAS No. 160 are required to be adopted prospectively, except the following provisions must be accepted retrospectively:
1. | Reclassifying noncontrolling interest from the “mezzanine” to equity, separate from the parents’ shareholders’ equity, in the statement of financial position; and |
2. | Recast consolidated net income to include net income attributable to both the controlling and noncontrolling interests. That is, retrospectively, the noncontrolling interests’ share of a consolidated subsidiary’s income should not be presented in the income statement as “minority interest.” |
Further, effective January 1, 2009, we have changed our accounting policy of recognizing a gain or loss upon any future direct sale or issuance of equity by our subsidiaries if the sales price differs from our carrying amount to be in accordance with SFAS No. 160, in which a gain or loss will only be recognized when loss of control of a consolidated subsidiary occurs. In January 2009, we sold approximately 13.6 million shares of CDI common stock to CDI for $86 million. This transaction constituted a single transaction and was not part of any planned set of transactions that would result in us having a noncontrolling interest in CDI and reduced our ownership in CDI to approximately 51%. Since we retained control of CDI immediately after the transaction, the approximate $2.9 million loss on this sale will be treated as a reduction of our
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equity in our consolidated balance sheet. Any future transactions would result in us losing control of CDI and accordingly the gain or loss on those transactions will flow through our earnings. As discussed in “Subsequent Events” above and in Note 25 of Exhibit 99.3 to this Current Report on Form 8-K, in June 2009 we sold approximately 21.6 million shares of CDI common stock held by us upon completion of an underwritten secondary public offering and a stock repurchase transaction with CDI. As a result of these transactions, at the time of the filing of this Current Report on Form 8-K we own approximately 28% of CDI’s issued and outstanding shares of common stock.
In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS No. 161”). SFAS 161 applies to all derivative instruments and related hedged items accounted for under SFAS No. 133. SFAS No. 161 asks entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged, but not required. We adopted the provisions of SFAS No. 161 on January 1, 2009 and it had no impact on our results of operations, cash flows and financial condition.
In May 2008, the FASB issued FASB Staff Position (“FSP”) APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement) (“FSP APB 14-1”). The FSP would require the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. We adopted FSP APB 14-1 on January 1, 2009. FSP APB 14-1 requires retrospective application to all periods reported (with the cumulative effect of the change reported in retained earnings as of the beginning of the first period presented). The FSP does not permit early application. This FSP changes the accounting treatment for our Convertible Senior Notes. FSP APB 14-1 will increase our non-cash interest expense for our past and future reporting periods. The effects of the adoption of this accounting standard are summarized in Note 2 of Exhibit 99.3 of this Current Report on Form 8-K.
In June 2008, the FASB issued FSP Emerging Issues Task Force 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). This FSP would require unvested share-based payment awards containing non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) to be included in the computation of basic EPS according to the two-class method. We adopted FSP EITF 03-06-1 on January 1, 2009. FSP EITF 03-06-1 requires all prior-period EPS data presented to be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the provisions of this FSP. FSP EITF 03-6-1 does not permit early application. This FSP changes our calculation of basic and diluted EPS and lowered our previously reported basic and diluted EPS as summarized in Note 2 of Exhibit 99.3 of this Current Report on Form 8-K.
Also in June 2008, the FASB issued Emerging Issues Task Force Issue No. 07-5, Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock (“EITF 07-5”). This issue addresses the determination of whether an instrument (or an embedded feature) is indexed to an entity’s own stock, which is the first part of the scope exception in paragraph 11(a) of SFAS No. 133. If an instrument (or an embedded feature) that has the characteristics of a derivative instrument under paragraphs 6–9 of SFAS No. 133 is indexed to an entity’s own stock, it is still necessary to evaluate whether it is classified in shareholders’ equity (or would be classified in shareholders’ equity if it were a freestanding instrument). This issue is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application by an entity that has previously adopted an
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alternative accounting policy is not permitted. While we do not believe the adoption of this statement will have a material effect on our financial statements, we continue to assess its potential impact on our financial statements.
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